This invention relates to methods and apparatus for treating underground formations to remove formation damage.
The production of hydrocarbons from underground reservoirs is often hampered by a damaged zone in the reservoir rock around the well bore.
These damage mechanisms include:
1. Drilling damage caused by the high velocity of drilling fluids passing through the jets in the drilling bit which can force liquid and particulate matter beyond the well bore out into the reservoir pore spaces.
2. Plugging of the pore spaces in the reservoir region immediately around the drilled well bore can be caused by formation rock material from the drilling process. These drill cuttings and fines can be forced into the pore spaces of the surrounding rock by several mechanisms; the rotation of the drill string and the weight of that drill string can put very high forces on particulate matter trapped between the drill string and the face of the well bore, compacting it into the pore spaces of the formation; or the pressure of the fluid in the well bore, which is normally higher than the pressure in the surrounding reservoir, can force drilling fines beyond the compaction zone and into the surrounding pores
3. Plugging of the pore spaces around the well bore can also be the result of particulate matter added to the drilling fluids to create a filter cake around the well bore which is intended to minimize the leak off of liquids into the surrounding reservoir. The mechanisms that force this particulate matter into the pore spaces are identical to those that cause damage from drilling fines, notably pressure, force and velocity.
4. Pore space reduction can occur as a result of alteration to the reservoir materials in the region surrounding the well bore. The most well known damage of this type is caused by clays in the reservoir which absorb fluids, most often water, and swell in physical size. This swelling reduces the size of the pore spaces and often reduces the permeability to the flow of reservoir hydrocarbons. This type of damage is often very difficult to remove or alter, and usually requires a hydraulic fracture with compatible fluids to bypass the damaged zone.
5. Fluid blockage in the region around the well bore results when the naturally occurring fluids in the reservoir are replaced by fluids injected during drilling or well service operations. Drilling fluids, fresh water, salt water, acids, acid reaction products, and other chemicals that are used in well operations can result in fluid blockage. These fluids can alter the surface tension between the rock and the fluid, which can have a dramatic impact on fluid to mobility and production. Emulsions and colloidal suspensions are two specific types of fluid blockage.
The development of horizontal drilling technology has provided additional challenges with respect to formation damage. In vertical wells, it normally only takes a matter of hours to drill through a hydrocarbon bearing formation and establish a stable filter cake on the face of the well bore to prevent further damage due to migration of solids and fluids. In horizontal wells however, drilling of the producing formation can take several days or longer which means that the formation is exposed to drill cuttings, drilling fluids and pressure for a much longer period of time than a conventional vertical well. The filter cake which helps to prevent fluid loss and invasion of particulate matter into the formation is much more susceptible to being removed by the weight, rotation and axial movement of the drill pipe tool joints. This can lead to a damaged region around the well bore which is much larger in areal extent and is more severely damaged than is the case for a vertical well bore.
In practice, damage removal in producing hydrocarbon reservoirs has been achieved through the use of primarily two techniques, acidizing and hydraulic fracturing. In carbonate reservoirs, acid injection to dissolve some of the rock material has proven to be effective in many situations. It is generally only when the damage is so severe as to prevent any injection of acid into the formation, that acid does not reduce the damge and improve production.
The use of acid to remove damage in reservoirs which have an active water drive can result in very serious production problems if the acid opens up channels into the water bearing portion of the reservoir. This situation can lead to very high water production levels which may render the well uneconomic to produce.
In sandstone reservoirs, acid is much less effective in reducing damage, particularly if the damaged region around the well bore is relatively deep or if the damage is severe. It is common practice in sandstone reservoirs to use hydraulic fracturing to create a fracture in the formation which extends beyond the region of damage and provides a flow channel from the undamaged formation to the well bore.
Virtually all well stimulation methods are based upon providing a pressure surge in the well bore or in the formation. One of the first methods utilized for oil well stimulation involved dropping containers of nitroglycerin down wells, which caused a high pressure surge when the nitro-glycerin exploded. Even acidizing and fracturing operations on wells can be classified as surge techniques since they employ the use of positive pressure across the well bore to formation interface. Numerous other surge techniques have been developed over the years including, underbalanced perforating systems, overbalanced explosive xe2x80x9cStress-Fracxe2x80x9d type systems, drop bar surge completion techniques, and more recently, extreme overbalanced perforating systems.
Some of these techniques use a long pressure cycle and some of them use an extremely short pressure cycle of less than a second. They generally use either a positive or a negative pressure differential across the well bore to formation interface, but not both. The pressure surge initiation can be either at surface or down hole in close proximity to the formation face. These techniques can involve the injection of solids (fracturing), liquids (acidizing) or gases (perforating) across the well bore formation interface.
It is common in the industry during stimulation operations that involve pumping fluid into the formation, to use a tubing string to convey the treating fluids to the well bore adjacent to the formation. This provides more control over displacement of the fluids, allows higher treating pressures and allows packers and other down hole flow control devices to be utilized. The tubing can be either jointed tubing or continuous coiled tubing.
It is also common in the industry to utilize sealing elements such as packers to isolate a segment of the well bore which can be xe2x80x9cselectivelyxe2x80x9d stimulated, without stimulating the remainder of the well bore. A single sealing element can be used to divide the well bore into two regions, the first region being below the sealing element and the second region being above the sealing element. Two sealing elements can be utilized to isolate a smaller region of the well bore from the regions below the lower packer and above the upper packer. Down hole devices such as fluid control valves, circulating valves and packer inflation valves which function either by mechanical or hydraulic means are well known in the industry.
In horizontal wells with long open hole sections of up to several thousands of feet, it can be appreciated that without selective stimulation tools, all treating fluids will follow the path of least resistance or least formation damage. As a result, it is possible for all of the stimulation fluids to enter the formation at the same point, and that no stimulation of the remaining formation will occur. Both gross stimulation techniques and selective stimulation techniques for treatment of horizontal wells are commonly practised.
U.S. Pat. No. 4,898,236 and Canadian patent No. 1,249,772 to Sask discloses a drill stem testing system which includes inflatable packers to isolate well bore regions for evaluation. Sask also discloses electrically operable valves for allowing fluids to flow between the various regions within and surrounding the down hole drill stem testing apparatus. However, it should be noted that Sask discloses the use of two position electrically operable valves which are biassed to one position, which necessitates the use of multiple electrically operable valves to accomplish the tasks required for drill stem testing operations.
Sask also discloses the use of an electrically operable pump for withdrawing fluids from the well bore and providing those fluids under pressure to expand inflatable type packers.
In a long horizontal well bore there is often a significant amount of particulate matter which in a vertical well would fall to the bottom of the well bore. Any packer inflation means utilizing well bore fluids for expanding packers in a horizontal well has the inherent risk of plugging either the pump or the packers with well bore particulate materials, particularly where the packers must be expanded a number of times to selectively evaluate or stimulate discreet segments of the well bore.
The present invention differs from what is taught in the prior art, in that in one aspect of the invention it teaches a method of removing formation damage through the controlled injection of fluids into the formation, followed by a controlled sudden release of pressure in the formation, an under-balanced surge, which causes fluid and damaging materials to flow back into the well bore. This method is most effective when repeated more than once. Its effectiveness in the removal of formation damage and subsequent improvement in fluid production is due to one or more of the following factors.
1. A method of removal of the solid, liquid or multi-phase materials causing the damage in the formation is preferable to and more effective than a method of simply dispersing this damaging material further into the formation. Creating a positive pressure surge into the formation tends to force materials deeper into the formation, whereas creating a negative pressure surge from the formation to the well bore tends to remove materials into the well bore. It is therefore better to utilize a negative pressure differential from the formation to the well bore to obtain the best stimulation results.
2. The ability to control the surge at the formation face, rather than at the surface, is preferred since it allows for more instantaneous release of the pressure, resulting in higher velocities in the near well bore region where the formation damage exists.
3. The use of nitrogen or other gas as a stimulation fluid provides deeper penetration into the formation as a result of the ability of gas to penetrate smaller pore space and openings within the formation.
4. The expansion and low density of gases can be used to create significantly higher fluid velocities in the area surrounding the well bore, when the pressure on the formation is released during the surge cycle, than can be achieved with liquid treatments. This gas expansion also means that the higher velocity will be maintained for a longer time duration than if liquid is injected. The lower density of gas, the ability to vent gas flowing into the well bore at surface, and the lack of a hydrostatic pressure buildup, means that a higher pressure differential can be maintained between the well bore and the formation.
5. If one surge can improve productivity through damage removal, then repeated surges should provide even more thorough damage removal. It is highly unlikely that all formation damage will be removed through a singular surge.
6. The use of gas can be effective in fluid blockage or where emulsions have formed because the gas molecules are smaller and can diffuse into the liquids. When the pressure is released, the gas molecules will expand and will force some of the liquid to move from the formation into the well bore along with the gas. Repeated surges can result in significant liquid blockage removal.
For the reasons stated above, a preferred embodiment of the present invention utilizes gas as a stimulation fluid. However, liquids or multiple phase fluids can also be utilized with the method of this invention.
In a further aspect of the invention, in order to provide multiple surge capability using gas, and to be able to inject the gas and then very quickly surge it back into the well bore, two fluid channels are provided. One fluid channel is used for injection of fluids into the reservoir and a second is used for removal of fluids and solids from the formation. Prior art stimulation practices were prevented or severely limited from providing this capability since injection and removal had to take place in the same flow path.
In a further aspect of the invention, a down hole valve or series of valves is provided to control the flow of fluid from the injection fluid channel into the formation and from the formation back into the return fluid channel.
Although it is possible to inject fluids using prior art technology and it is possible to surge a well once using under-balanced perforating or rupture disk techniques, the ability to surge a well effectively more than once with a single flow channel can not be accomplished for several reasons.
The first limitation is that in order to flow the well back, the pressure must be released from the tubular string. If liquid has been injected, the pressure which has been applied at surface can be released very quickly since liquid is relatively incompressible, and the pressure down hole will decrease by the same amount that the surface pressure decreases. However, the pressure at the lower end of the tubing, which is still being applied against the formation, will be equal to the hydrostatic pressure of the liquid column in the tubular string. In most instances, this hydrostatic pressure will be greater than the reservoir pressure and the resulting surge will be minimal and relatively ineffective.
If gas has been injected into the formation, then as the pressure is released at surface, the expansion of the gas in the tubing will set up a pressure gradient along the tubing as virtually all of the gas injected into the tubing will flow back out of the tubing. Therefore it will take a long time for the pressure at the down hole end of the tubing to decline and this decline will be very gradual. The result will be a low fluid velocity in the formation and the lack of any effective xe2x80x9csurgexe2x80x9d to force damaging materials from the formation into the well bore.
If a valve is placed down hole and closed after the injection has stopped, the gas pressure in the formation can be better maintained while the tubing pressure is bled off and will provide the ability to surge the formation when the valve is opened. However, a significant amount of the injection pressure may be dissipated into the formation during the lengthy time period required to bleed down the tubing pressure.
The release of pressure from the tubing and re-pressurization for another injection cycle requires significant time, particularly if gas is utilized. This is operationally more complex than the method of the present invention and increases the costs of the treatment, especially as a result of substantially higher gas volumes required.
It can be appreciated from the preceding discussion that the use of a down hole fluid control valve to control the injection of fluids into the formation and to control the release of fluids from the formation would have a beneficial impact on the development of a surge stimulation method.
For the preceding reasons, it should also be appreciated that a surge technique will be more effective if a second fluid channel exists in which the pressure can be released back to surface. There are several options that provide the ability to achieve a dual flow configuration.
1. Two strings of jointed tubing, run side by side, can be utilized. The fluid control valve(s) allow injection down one string and flow back up the other string.
2. Concentric string tubing comprised of coiled tubing inside of jointed can be used The fluid control valve(s) allow injection down the outer string and flow back up the inner string.
3. Concentric string tubing with coiled tubing inside of coiled tubing can be used. The fluid control valve(s) allow injection down the outer string and flow back up the inner string.
4. A single string of tubing can be utilized in conjunction with the well bore annulus. This requires that the well bore annulus be essentially empty of liquid, or with a low fluid level. The stimulation apparatus disclosed in the present invention provides this configuration.
In a further aspect of the invention, there is disclosed a novel downhole valve system, in which a series of ports are selectively coupled together to allow flow of fluids through the valve system. The use of clean fluids supplied down a tubing string also provides a distinctive advantage in reducing the risk of plugging the inflation system.
In an aspect of the valve system invention, there is proposed the use of a micro-controller and an electrically driven valve. These features have distinct advantages over mechanically or hydraulically controlled valves. For a preferred embodiment of the method being disclosed in this patent, four mechanical or hydraulic valves would be required for complete operation. In order to control these valves individually would require very complex mechanical or hydraulic operations. Mechanically, only tension or compression can be utilized since it is not possible to rotate coiled tubing. In a well with a long horizontal section, the ability to precisely apply tension or compression for manipulating a valve can be difficult if not impossible due to severe friction between the coiled tubing and the well bore.
The use of hydraulic pressure for sequencing four distinct valves would require a complex array of pressure settings and could severely limit the flexibility of the treatment procedure as compared to the singular multiple position fluid control valve disclosed in this patent. In one aspect of the method of the invention, the surge stimulation method uses a short injection cycle followed by the immediate release of pressure. The use of a multiple position fluid control valve has a level of simplicity in design which will effect reliability of the stimulation tool in a very positive manner.
In another aspect of the invention, a wireline conductor between the surface computer and the down hole apparatus allows both power and control commands to be sent from surface to the down hole apparatus. Data measurements in the down hole apparatus, such as pressure and temperature, can be sent back to the surface computer. The importance of real time data in drill stem testing operations is discussed in the Sask patent.
In a further aspect of the invention, there is provided a method for stimulating the production of fluids from subsurface regions surrounding a well bore. This method relates to the technique of injecting and removing stimulation fluids from the formation in a controlled surging method.
In one aspect of the invention, fluids are injected at pressures higher than the formation pressure in order to create a zone around the well bore of higher pressure than what is in the formation. This injection period to create a positive surge, will be for a relatively short period of time, normally in the order of minutes. The injection period may or may not be followed by a brief transition time to allow the injected fluid to mix with and associate with the formation fluids or formation materials. The pressure in the formation is then released to a conduit in the well bore which creates a negative surge and allows the pressure to fall back to or less than the native formation pressure. This surge process can be repeated any number of cycles to facilitate more complete removal of the formation damage around the well bore.
In a further aspect of the invention, there is provided a method for evaluating the permeability and formation damage in the porous rock around a well bore. This method relates to the use of a single string coiled tubing and a down hole assembly which includes a microcontroller, an electrically operable fluid control valve and electrically operable pressure sensing devices which allow for real time pressure transient analysis techniques before, during and after formation stimulation treatments.
In another aspect of the invention, a down hole evaluation and stimulation system is provided which allows these methods to be performed in a well. The down hole tool is lowered into the well at the end of a string of segmented tubing or continuous coiled tubing. In one aspect of the invention, the tool comprises of a number of elongated housings which direct fluid between the various regions around the down hole tool. An inventive aspect of the tool is a valve arrangement which directs flow between the various separate regions This valve arrangement allows for the injection of high pressure fluids down a conduit from surface into the subsurface reservoir. The arrangement also allows the flow of injected fluids to be stopped at the down hole tool without bleeding back the pressure in the conduit. The valve arrangement is capable of releasing the pressure in the subsurface formation back to a second conduit which is also connected to the surface.
These and other aspects of the invention are described in the detailed description and claimed in the claims that follow the detailed description.